Emission control system

ABSTRACT

Methods of treating mercury contaminated gas comprising: introducing a hydrogen halide selected from HBr and HI into a mercury contaminated gas stream containing a quantity of particulate matter at an introduction rate sufficient to create a concentration of at least 0.1 ppmvd; wherein greater than 50% of all particulate matter in the mercury contaminated gas stream is a native particulate matter; contacting a quantity of active bromine with the native particulate matter; creating a doped particulate matter; coating a filtration media with the doped particulate matter; and passing a portion of the mercury contaminated gas stream through the doped particulate matter on the filtration media and other related methods are disclosed herein.

This application claims the benefit of provisional application No.61/438,404 filed on Feb. 1, 2011 and entitled “Emission Control System.”This application claims the benefit of provisional application No.61/527,949 filed on Aug. 26, 2011 and entitled “HBr Treatment.”

As used herein, references to HBr injection concentration are recordedas HBr on a parts per million dry flue gas by volume basis (ppmvd).Indications of ppmvd concentrations represent only the gas phaseconcentration including constituents entrained in the gas but excludingany constituents not entrained in the gas. Thus HBr (or active bromine)attached to gas entrained fly ash would be included in HBr ppmvd numbersbut HBr in fly ash attached to a conduit wall would not be included.Accordingly, for the purposes of this disclosure, indications of HBrconcentration in the units ppmvd are calculated as if any HBr bound toentrained fly ash or other entrained particulate matter were in thevapor phase. In cases where other compounds are injected or the gas isnot a flue gas, the calculation of ppmvd remains the same. As usedherein, gas concentrations indicated in the units μg/m³ representconcentration at standard conditions of 68° F. and 14.696 psi.

Methods of treating mercury contaminated gas described herein may, forexample, comprise introducing a hydrogen halide selected from HBr and HIinto a mercury contaminated gas stream containing a quantity ofparticulate matter at an introduction rate sufficient to create aconcentration of at least 0.1 ppmvd; wherein greater than 50% of allparticulate matter in the mercury contaminated gas stream is nativeparticulate matter; contacting a quantity of active bromine with thenative particulate matter; creating a doped particulate matter; coatinga filtration media with the doped particulate matter; and passing aportion of the mercury contaminated gas stream through the dopedparticulate matter on the filtration media. In a related method, thehydrogen halide selected from HBr and HI is HBr. In a related method,the introducing of a hydrogen halide selected from HBr and HI may occurat a point where the mercury contaminated gas stream is less than 750°F. In a related method, the introduction of a hydrogen halide selectedfrom HBr and HI occurs at a point where the mercury contaminated gasstream is greater than 180° F. In another related method, the mercurycontaminated gas stream is a byproduct of the combustion of coal havinga chlorine content of less than 300 ppm by weight and a mercury contentgreater than 50 ppb by weight. In a further related method, theintroduction of a hydrogen halide selected from HBr and HI is at anintroduction rate creating a concentration of at most 15 ppmvd.

Methods of treating mercury contaminated gas described herein may, forexample, comprise introducing dilute aqueous HBr into a mercurycontaminated gas stream containing a quantity of particulate matter atan HBr introduction rate sufficient to create a HBr concentration of atleast 0.1 ppmvd; contacting a quantity of active bromine with a portionof the quantity of particulate matter; creating a doped particulatematter from the quantity of active bromine and the quantity ofparticulate matter; and inducing electrostatic forces thereby removinggreater than 50% of the doped particulate matter from the mercurycontaminated gas stream. In a related method, mercury is collected onthe doped particulate matter. In a further related method, theelectrostatic forces occur within an electrostatic precipitator. In astill further related method, the introduction of dilute aqueous HBr isat an introduction rate creating a HBr concentration of at most 10ppmvd.

Methods of treating mercury contaminated gas described herein may, forexample, comprise introducing a mercury contaminated gas into a conduit;wherein the conduit comprises HBr susceptible materials; wherein themercury contaminated gas has an initial quantity of mercury; wherein theconduit has an inner surface; injecting a quantity of dilute aqueous HBrinto the conduit; wherein the injection of the quantity of diluteaqueous HBr is through a plurality of nozzles at an HBr injection ratesufficient to create a HBr concentration of at least 0.1 ppmvd; whereina spray pattern of the plurality of nozzles covers a majority of across-section of the conduit; wherein there is no substantialaccumulation of aqueous HBr on the inner surface; and contacting themercury contaminated gas with a media thereby removing at least 50% ofthe initial quantity of mercury from the mercury contaminated gas. In arelated method, the injection of the quantity of dilute aqueous HBroccurs at a point where the mercury contaminated gas is between 180° F.and 750° F. In a further related method, the injection of the quantityof dilute aqueous HBr occurs at a point where the mercury contaminatedgas is between 180° F. and 750° F. In a still further related method,the plurality of nozzles is a plurality of dual fluid nozzles and theHBr concentration in the dilute aqueous HBr is greater than 0.25%. In astill further related method, the injection of the quantity of diluteaqueous HBr is through a plurality of nozzles at an HBr injection ratecreating a HBr concentration of at most 10 ppmvd.

Methods of treating a mercury contaminated gas described herein may, forexample, comprise introducing active bromine into a treatment zone;passing a mercury contaminated gas stream through the treatment zone;wherein the mercury contaminated gas stream contains nitrogen; wherein aresidence time of the active bromine in the treatment zone is at least1.1 times that of a residence time of the nitrogen in the treatmentzone; and removing at least 50% of the mercury contained in the mercurycontaminated gas stream from the mercury contaminated gas stream with aparticulate control device. In a related example, active bromine may beintroduced into the treatment zone at an introduction rate that createsan active bromine concentration of between 0.1 ppmvd and 10 ppmvd. In aseries of related examples, the residence time of the active bromine inthe treatment zone may be at least 1.2 times, 1.5 times or even 2.0times that of a residence time of the nitrogen in the treatment zone.

Methods of treating flue gas described herein may, for example, compriseintroducing active bromine into a treatment zone; introducing ammoniainto the treatment zone; passing a quantity of flue gas having aninitial ash content and having an initial mercury content through thetreatment zone; collecting at least 80% of the initial ash content in aparticulate control device; and collecting at least 50% of the initialmercury content in the particulate control device. In a related example,the ash collected in the particulate control device has a total ammoniacontent of at least 40 ppm by weight. In a further related example, theash collected in the particulate control device contains at least 60% ofthe initial mercury content. In a still further related example, activebromine is introduced into the treatment zone at an introduction ratethat creates an active bromine concentration of between 0.1 ppmvd and 10ppmvd.

In various embodiments described herein, ash compositions having specialproperties are prepared. Sometimes these ash compositions are referredto as “conditioned ash sorbent” As that term is used herein,“conditioned ash sorbent” designates ash having an active brominecontent greater than 20 ppm by weight. As that term is used herein“active bromine” designates HBr and its direct disassociation productsthat contain a bromine atom. Examples of compounds that may becharacterized as “active bromine” include HBr, Bromine radical, andBr⁻¹. In addition to the basic active bromine concentration ofconditioned ash sorbent, conditioned ash sorbent as practiced in themany individual variations of embodiments described herein may have anactive bromine content of greater than 60 ppm, greater than 100 ppm,greater than 200 ppm, less than 2000 ppm, less than 5000 ppm, and lessthan 10,000 ppm. Treatment of flue gas according to the methodsdescribed herein may, for example, cause mercury to be removed from theflue gas by attachment to fly ash without any substantial re-emission ofmercury before that fly ash is removed from the flue gas. Treatment offlue gas as described herein may cause greater than 90% of all bromineatoms in the flue gas to be in the form of active bromine throughout thezone in which the mercury containing flue gas is being treated.Emissions of filterable particulate matter may be reduced by treatmentsdescribed herein in systems having an electrostatic precipitator.

Methods of treating flue gas described herein may, for example, comprisepassing a flue gas through a treatment zone; introducing a hydrogenhalide selected from HBr and HI into the treatment zone at a ratesufficient to create a concentration of at least 0.1 ppmvd; producing aconditioned ash sorbent on a plurality of surfaces of the treatment zonesuch that the treatment zone has a treatment area to flue gas flow ratioof at least 0.3 min/ft; and continuing the introduction of the hydrogenhalide selected from HBr and HI into the treatment zone until thetreatment zone attains a cumulative injection level of 60 ppmvd*hrs. Ina related example, the hydrogen halide selected from HBr and HI is HBr.In a further related example, the introducing of the hydrogen halideselected from HBr and HI into the treatment zone is at an introductionrate that creates an active bromine concentration of less than 10 ppmvd.In distinct related embodiments, the treatment area to flue gas flowratio may be at least 0.3 min/ft, at least 0.5 min/ft, and at least 3.0min/ft.

A method of treating a mercury contaminated gas described herein may,for example, comprise combusting a fuel containing at least 50 ppbmercury by weight; combusting a substantial quantity of a treatmentcomposition; wherein the treatment composition is selected from:2-(bromomethyl)oxirane; 1-bromopropan-2-one; 1-bromobutane;2-Bromobutane; 1-bromo-2-methylpropane; 1-bromo-3-methylbutane;2-bromo-2-methylbutane; 1-bromopentane; 2-bromopentane; 2-bromopentane;1-bromo-2-ethoxyethane; bromobenzene; 2-bromopyridine; dibromomethane;1,2-dibromoethene; 1,1-dibromoethane; 1,2-dibromoethane;2,2-dibromoacetonitrile; 2,3-dibromoprop-1-ene; 2-bromoacetyl bromide;1,2-dibromopropane; 1,3-dibromopropane; 1,3-dibromobutane;1,4-dibromobutane; 1,3-dibromopropan-2-ol; 2,3-dibromopropan-1-ol;1,4-dibromopentane; 1,5-dibromopentane; 1-bromo-2-(2-bromoethoxy)ethane;(1R,2R)-1,2-dibromocyclohexane; 1,6-dibromohexane; dibromomethylbenzene;1,8-dibromooctane; 1,1,2-tribromoethene; 2,2,2-tribromoacetaldehyde; and1,1,2,2-tetrabromoethane; and comingling at least one product from thecombusting of the fuel and at least one product from the combusting ofthe substantial quantity of the treatment composition. In a relatedexample, the treatment composition is bromoethane. In another relatedexample, the treatment composition is bromoform. In another relatedexample, the treatment composition is dibromomethane. In another relatedexample the treatment composition is 1,2-dibromoethane. In anotherrelated example, the treatment composition is 1,2-dibromoethene.

As may be appreciated from the examples below, various embodimentsdescribed herein may have one or more of the following features: Inseparate but related embodiments, the temperature of the flue gasimmediately prior to the point of injection of the aqueous solution ofHBr may be less than 1100° F., less than 750° F., and less than 710° F.In separate but related embodiments, the temperature of the flue gasimmediately prior to the point of injection of the aqueous solution ofHBr may be greater than 180° F., greater than 200° F., greater than 220°F., greater than 325° F., and greater than 425° F. As an example, thetemperature of the flue gas immediately prior to the point of injectionof the aqueous solution of HBr may be about 700° F. The exhaust gas maybe an exhaust gas from a calcining process. The exhaust gas may also bean exhaust gas from an ore roasting process. The flue gas may further beflue gas from a coal-fired power plant or a boiler. In a series ofdistinct but related examples, methods described herein may be used totreat coal having a chlorine content of less than 500 ppm by weight,coal having a chlorine content of less than 300 ppm by weight, and coalhaving a chlorine content of less than 100 ppm by weight. Treatmentsdescribed herein may oxidize greater than 50% of any Hg(0) present inthe flue gas into Hg(II) and may oxidize greater than 80% of any Hg(0)present in the flue gas into Hg(II). Coal combusted and subjected totreatments described herein may have a mercury content of greater than0.05 μg per gram coal, greater than 0.10 μg per gram coal or evengreater than 0.15 μg per gram coal. Flue gases treated by the methodsdescribed herein may have a mercury content of greater than 1.0 μg/dscm,greater than 2.0 μg/dscm, or even a mercury content of greater than 4.0μg/dscm. While examples described herein illustrate the effectiveness ofHBr, it is also contemplated that compositions such as HF, HCl, HBr, HI,F₂, Cl₂, Br₂, and I₂ may be utilized in a similar manner with varyingdegrees of effectiveness. In certain embodiments, the halogen containingadditive supplied may be supplied to the flue gas at 300 ppm or less ofthe weight of total of coal and additive supplied (i.e. roughly lessthan 0.3 g HBr added per kg coal combusted). In separate but relatedembodiments, the additive may be supplied at 250 ppm or less, at 200 ppmor less, at 200 ppm or less, at 150 ppm or less, or even at 100 ppm orless. In many practiced embodiments, less than 20 weight percent of themercury in the coal is released to the atmosphere and in some cases lessthan 10 weight percent of the mercury in the coal was released to theatmosphere.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a chart describing features of various examples.

FIGS. 2 and 3 represent the layout of the plant tested in Examples1A-1E.

FIG. 4 is a plot of total mercury concentration during the test ofExample 1B.

FIG. 5 is a plot of total mercury concentration during the test ofExample 1C.

FIG. 6 is a plot of total mercury concentration during the test ofExample 1E.

FIG. 7 represents the layout of the plant tested in Example 2.

FIG. 8 is a plot of mercury oxidation against HBr injection rates fromthe testing of Example 2.

FIG. 9 is a plot of ammonia injection rate and the NOx emission factoragainst HBr injection concentration from Example 2.

FIG. 10 is a view of the internal structure of an SCR coated with HBrtreated ash.

FIG. 11 is a view of the internal structure of an ESP coated with HBrtreated ash.

FIG. 12 represents the layout of the plant tested in Example 5.

FIG. 13 shows oxidation results from Example 5.

FIG. 14 is a plot of total mercury emissions against HBr dosing for thetests of Example 5.

FIG. 15 is a plot of total mercury removal against cumulative HBr dosingfor the tests of Example 5.

FIG. 16 is a plot of stack mercury concentrations versus cumulative HBrdosing for the tests of Example 5.

FIG. 17 is a drawing of the baghouse described in Example 6.

FIG. 18 is a drawing of the internals of the baghouse described inExample 6.

FIG. 19 represents the layout of the plant tested in Example 7.

FIG. 20 is a plot of stack mercury concentrations during the tests ofExample 7.

FIG. 21 depicts elements of an HBr supply system described in Example13.

FIG. 22 depicts an operational layout for elements of an HBr supplysystem.

FIG. 23 depicts an operational layout for elements of an HBr supplysystem.

FIG. 24 depicts an operational layout for elements of an HBr supplysystem.

FIGS. 25A and 25B depict an operational layout for elements of an HBrsupply system.

FIG. 26 depicts a configuration for a HBr distribution system.

FIG. 27 depicts configuration for handling HBr and HBr deliveries.

FIG. 28 depicts a dual fluid nozzle.

FIG. 29 depicts spray characteristics for the dual fluid nozzle.

FIG. 30 is a perspective view of a duct into which HBr is beinginjected.

FIG. 31 is a cross-section of a duct in the area of injection.

FIG. 32 is a cross-section of a duct in the area of injection.

FIG. 33 is a cross-section of a spray pattern with exaggerated dropletcharacteristics.

FIG. 34 represents an experimental apparatus for loading fly ash withmercury and HBr.

FIG. 35 is a configuration in which organohalogens may be combusted forthe treatment of flue gas.

FIG. 36 is a configuration in which organohalogens may be combusted forthe treatment of flue gas.

FIG. 37 is a configuration in which organohalogens may be combusted forthe treatment of flue gas.

FIGS. 38A-38E present organohalogens that may be combusted for thetreatment of flue gas.

FIG. 39 depicts a calcining process with an HBr injection system.

FIG. 40 depicts a pollution control system for coke ovens with HBrinjection.

EXAMPLES

A wide variety of commercial scale coal-fired power plants and steamplants were tested to determine the viability of HBr injection underdifferent operating conditions and test configurations. FIG. 1 of thedrawings is a representation of the wide variety of configurationstested. In each of the examples of FIG. 1, a significant reduction inmercury emissions was accomplished through HBr injection and in manycases other benefits were demonstrated. As used in FIG. 1 and elsewherethroughout this disclosure, “SCR” indicates the presence of a selectivecatalytic reduction system, “SNCR” indicates the presence of a selectivenon-catalytic reduction system, “FF/BH” indicates the presence of afabric filter or baghouse, “ESP” indicates the presence of anelectrostatic precipitator, “DFGD” indicates the presence of dry fluegas desulfurization, “WFGD” indicates the presence of wet flue gasdesulfurization, “PRB” indicates that powder river basin coal was usedas fuel, “Lignite” indicates that lignite coal was used as fuel,“Bituminous” indicates that by bituminous coal was used as fuel,“Biomass” indicates that the biomass was used as fuel, “Trona” indicatesthat trona was used to absorb flue gas constituents, “Carbon” indicatesthat carbon was used to absorb flue gas constituents, “Steam” indicatesthat the plant was used primarily for the generation of steam, and“Electric” indicates that the plant was used primarily for thegeneration of electricity. FIG. 1 also lists approximate full loadgenerating capacity for the plants tested as megawatts with steamgenerating plants represented as megawatt equivalents.

Examples 1A-1E

A series of experiments were conducted on a plant having generalcharacteristics described in FIG. 1. Emission characteristics, inparticular mercury emissions, were evaluated under a variety ofoperating conditions. During the evaluation associated with Examples1A-1E, halogenated fluids and trona were applied at various points inthe process. Testing and observations associated with Examples 1A-1Ewere over a four-day period.

The pulverized coal boiler tested had a nominal unit capacity of 670 MWand was burning sub-bituminous coal. NO_(X) was controlled using aselective catalytic reduction system. A cold-side electrostaticprecipitator provided particle control. The embodiment of FIGS. 2 and 3represents the configuration on which the tests of Examples 1A-1E wereconducted. Pulverized coal boiler 1100 and economizer 1105 precede theflue gas treatment steps of the process. The flue gas is split into twoseparate ducts, duct A 1110 and duct B 1112 where treatment forpollutant control is conducted. Injection of HBr solution associatedwith Examples 1A-1E occurred at injection point 1115. No equivalentinjection occurred at the equivalent point in the duct B 1120. Tronainjection point 1133 was in duct A 1110 downstream of the SCR 1130. Thealternate location for Trona injection 1143 was between the airpreheater 1140 and the electrostatic precipitator 1150. Speciatedmercury testing 1155 was conducted at the exit of electrostaticprecipitator 1150 prior to the induced draft fan 1160 which vents tostack 1170.

As indicated in FIGS. 2 and 3, the HBr injection was performed prior tothe SCR system's Duct “A,” 1110 approximately 30 feet upstream of theammonia injection grid (AIG). The trona injection was performed upstreamand downstream of the air pre-heater (APH), depending on the specifictest objectives. Hg emission speciation was measured at Duct “A” 1110 ofUnit 3's ESP outlet 1150 while the stack Hg CEMS data was also beingdocumented. All Duct “A” Hg emission measurements were determined usingEPA Method 30B with speciation sorbent traps.

Mercury control was conducted in a two step process. The first step wasto promote Hg oxidation from Hg(0) to Hg(II) because Hg(II) is somewhatwater soluble and tends to bind with the surface area of fly ashparticles. Mercury oxidation may be effectively accomplished through theaddition of a halogen chemical additive. The chemical additivesdiscussed herein were demonstrated to provide a high degree of oxidationper unit mass of additive. In each of Examples 1A-1D, the chemicaladditive that was tested was an aqueous solution of HBr applied to theflue gas by the air atomizing nozzles described below.

Example 1A Baseline Testing (Day 1)

One set of speciated EPA Method 30B tests were conducted under theboiler's baseline operating conditions in the absence of either HBradditives or Trona. The baseline flue gas HgT was 5.28 μg/dscm (5.28micrograms HgT per dry standard cubic meter of gas), with 5.15 μg/dscm(97.5%) of the mercury having an oxidation or valance state of zero(Hg(0)). This is typical of powder river basin coal-fired applications,due to the low concentration of chlorine or other native oxidants in PRBcoal.

Example 1B HBr Testing (Day 2)

Four runs of testing were performed at the APH outlet under variousTrona/HBr injection conditions. The testing matrix and Hg removalresults can be found in Table 1. The total HBr injection time on day 2was 4 hours.

TABLE 1 Test Parameters and Results (Day 2) Run No. Solution & Hg(II)Hg(0) HgT* (Run Time) Injection Rate μg/dscm μg/dscm μg/dscm Run 1(1150- Trona@ 5300 lb/hr N/A N/A 6.15 1405) HBr (N/A) Run 2 (1515- Trona@ 7000 lb/hr 0.56 6.10 6.66 1614) HBr (N/A) Run 3 (1710- Trona @ 8500lb/hr 0.71 1.10 1.81 1830) HBr @ 45 ppmvd Run 4 (2001- Trona @ 8500lb/hr 0.62 1.33 1.95 2100) HBr @ 28 ppmvd *HgT represents total mercuryin all oxidation states.

During Runs 1 and 2, no HBr solution was injected, but trona wasinjected at a rate of just under 5300 lb/hr and 7000 lb/hr. Mercuryconcentrations at these rates were 6.15 μg/dscm HgT and 6.66 μg/dscmHgT, respectively. Run 2 results indicated that Hg(0) was at 6.10μg/dscm, which accounted for 92.3% of the total mercury (HgT).

After the first two runs, trona injection was set at 8500 lb/hr and theHBr injection was set at approximately 45 ppmvd (parts per million ondry volume basis) or (78 gallons per hour) for a period of two hours.The HBr/Trona combined injection yielded 82% Hg oxidation and 73% Hgremoval. The HgT and Hg(0) concentration was 1.81 μg/dscm and 1.10μg/dscm, respectively.

During Run 4, the HBr injection was reduced to 28 ppmvd or 49 GPH andwas maintained at this rate for a two-hour period. The ammonia wastemporarily stopped on the “A” side. This was to determine whether therewas any interference to the HBr operation from the NH₃ injection. TheHgT and Hg(0) concentrations were 1.95 μg/dscm and 1.33 μg/dscm,respectively. The HBr/Trona combined injection yielded 78% Hg oxidationand 71% Hg removal. Both the Trona injections and the HBr injectionswere stopped at 2100 hours. Based on a HBr injection point 30 ftupstream from the ammonia injection grid, no interference was observedin HBr performance when the ammonia injection was stopped.

The data trends from the stationary continuous emission monitoringsystems (CEMS) were also documented, and results are shown in FIG. 4.The mercury CEMS unit monitors HgT in the stack, after the flows of DuctA and Duct B have been recombined. As seen in FIG. 4, the unit wasbrought to a full load of approximately 700 MW for the test days and wasmaintained at that load throughout. FIG. 4 begins at midnight on day 2and runs until 0712 hours on day 3. The HgT concentration during thefirst two runs averaged 5.1 μg/dscm. Based on the baseline testing onday 1, the first two runs of parametric testing on day 2 and the Hg CEMSdata average, it is estimated that the native HgT emission concentrationvaried between 5 μg/dscm and 6 μg/dscm. Furthermore, it is estimatedthat prior to the HBr injection, the flue gas from both ducts containedaround 5.5 μg/dscm of HgT emission.

After the HBr injection of run 3 began, the Hg data trend showedimmediate removal, as recorded on the stationary Hg CEMS. During thelast two runs, the stack Hg concentration averaged 2.5 μg/dscm. The fluegas on the “A” side was treated while the flue gas on the “B” sideremained untreated. Given that the volumetric flow rates of gasesthrough Duct A and Duct B were approximately equal, based on a stack HgCEMS reading of 2.5 μg/dscm, the HgT concentration on the treated “A”side was approximately zero. The maximum total Hg removal on the “A”side was calculated to be above 95%, based on the stationary Hg CEMS.

After correcting for a bypass stream, total Hg removal in the treatedstream was calculated to be approximately 89%, based on the stationaryHg CEMS after Trona and HBr injections were stopped. As mentioned above,both the Trona and HBr injections were stopped at around 2100 hours. Thetotal Hg trend did not return to the baseline concentration (5.5μg/dscm) right away, based on the readings from the stack Hg CEMS. Asseen in FIG. 4, mercury concentration stayed below baseline from thepoint that HBr injection began until the following morning. Thisresidual effect may be attributable to the HBr chemical additivepreviously injected that was retained on the ash and SCR catalyst loadedinto the SCR.

Example 1C Day 3

On the third day of testing, the trona injection was moved from the ESPinlet to the APH inlet, and the unit was maintained at full load ataround 700 MW. The testing matrix and Hg results are summarized in Table2.

TABLE 2 Test Parameters and Results (Day 3) Run No. Solution & Hg(II)Hg(0) HgT (Run Time) Injection Rate μg/dscm μg/dscm μg/dscm Run 0 (0600-Trona (N/A) N/A N/A 1.22* 0630) HBr (N/A) Run 1 (1000- Trona@ 5300 lb/hr0.49 3.00 3.44 1100) HBr (N/A) Run 2 (1229- Trona @ 7000 lb/hr 0.38 3.933.98 1332) HBr (N/A) Run 3 (1526- Trona @ 8500 lb/hr 0.63 4.25 4.601620) HBr (N/A) *not representative of a baseline conditions due toeffects from the previous day.

As shown in Table 2, the recovery of Hg concentration remained belowbaseline conditions (between 5 μg/dscm and 6 μg/dscm) from theinjections of the previous day. At 0630, the baseline Hg was stillmeasured at 1.22 μg/dscm, which represented 78% total Hg removal hoursafter actual HBr injection ceased. At 1600 pm, while Trona injection wasunderway, the HgT emission was 4.88 μg/dscm. The stack CEMS data trendscan be found in FIG. 5. FIG. 5 which begins at 0930 hours on day 3 andends at 0000 hours on day 4, shows that during the Trona injection ofday 3 HgT levels were below baseline concentrations and that when Tronainjection ceased HgT levels dropped rapidly even further below baselineto approximately 2 μg/m³. This is evidence of the strong residualeffects of the HBr injected on the previous day, which was interruptedby sorption by trona during the period of trona injection.

At approximately 0930 hours, Trona injection was initiated upstream ofthe APH inlet. The stack Hg CEMS data averaged 2.4 μg/dscm. In order forthe stack HgT CEMS to read approximately 2.4 μg/dscm, the Hgconcentration on the “A” side would have to be almost zero. Thus, itcould be concluded that the total Hg removal was above 95% for thetreated duct (from the baseline Hg concentration of 5.5 μg/dscm), basedon the stationary Hg CEMS. CEMS data showed that the residual effects ofday 2 HBr injections lasted at least 16 hours. This included 4 hours ofactual injection and 12 hours of residual effect.

When the APH inlet Trona injection was started, the total Hgconcentration would increase; and immediately after the APH inlet Tronainjection was stopped, the Hg concentration would decrease. Not wishingto be bound by theory, the Trona may have interacted with the HBradditive, inhibiting the oxidation of Hg(0). Embodiments that alter theinteraction of Trona with HBr described in this example arecontemplated. For example, Trona may be injected further downstream toprovide sufficient residence time for the HBr solution to react withHg(0). Not wishing to be bound by theory, a potential cause of theobserved effect may include consumption of the HBr by the trona prior tothe promotion of Hg oxidation and/or consumption of HBr effecting theequilibrium of the oxidation reaction involving the Hg.

Example 1D Day 4

On the fourth day of testing, trona injection was resumed at the APHinlet at a constant rate of 8500 lb/hr, and the unit was maintained atfull load at around 700 MW from 0930 onward. Both trona and HBrinjections were started at around 0930 hours. There were four runs ofHBr injections (with Trona injections) at 5 ppmvd (8.8 GPH), 10 ppmvd(17.3 GPH), and 15 ppmvd (26 GPH), and one injection at 15 ppmvd (26GPH) with no Trona injection. The testing matrix and Hg results aresummarized in Table 3.

TABLE 3 Test Parameters and Results (Day 4) Run No. Solution & Hg(II)Hg(0) HgT (Run Time) Injection Rate μg/dscm μg/dscm μg/dscm Run 1 (0750-Trona (N/A) 1.31 1.77 2.99 0900) HBr (N/A) Run 2 (1303- Trona @ 8500lb/hr 0.94 3.24 4.18 1428) HBr @ 5 ppmvd Run 3 (1303- Trona @ 8500 lb/hr0.29 3.09 3.38 1428) HBr @ 10 ppmvd Run 4 (1610- Trona @ 8500 lb/hr 0.672.29 2.96 1545) HBr @ 15 ppmvd Run 5 (1849- Trona (N/A) 0.41 1.42 1.831934) HBr @ 15 ppmvd

Run 1 of day 4 was not fully representative of baseline conditionsbecause the unit was not operating at full load throughout the run.Under the various testing conditions of HBr injection, at the ESPoutlet, the total Hg was 4.18 μg/dscm, which yielded approximately 24%of total Hg removal with 5 ppmvd HBr injection; 3.38 μg/dscm, whichyielded approximately 39% of total Hg removal with 10 ppmvd HBrinjection; and 2.96 μg/dscm, which yielded approximately 46% of total Hgremoval with 15 ppmvd HBr injection. However, upon stopping the APHinlet Trona injection, the 15 ppmvd HBr injection yielded approximately67% of total Hg removal, and the ESP outlet HgT was 1.83 μg/dscm.

The Trona injection was stopped at around 0600 hours. The average stackHg concentration was approximately 2.2 μg/dscm. The CEMS results closelyagreed with the Run 4 sorbent trap results collected during the timeperiod where stack Hg concentrations continued to decline. For the stackHg CEMS to stabilize at around 2.2 μg/dscm, the Hg concentration on the“A” side would have to be essentially zero, which means more than a 95%total Hg removal. The HBr injection was finished at 1930 hours. Between1930 and 2000 hours, before the unit load was brought down, the stack Hgconcentration averaged 1.6 μg/dscm, yielding more than 95% total Hgremoval. This is yet another example of the observed residual effects ofHBr injection.

Example 1E Days 5-6

The HBr injection was finished at 1930 hours on day 4. However, thestack Hg CEMS still indicated that stack Hg concentrations were below2.5 μg/dscm for 45 hours on the two days following the test, day 5 andday 6. This corresponds to more than 95% of total Hg removal. FIG. 6displays data from this period. Removal of HgT was at least 80% with HBrinjection, both without Trona injection and when Trona was injectedprior to the ESP. CEMS results indicate that even greater removalefficiency, perhaps as high as 95%, was achieved. Tests associated withExamples 1A-1E indicate that HBr injection can be configured to removegreater than 80% of mercury from a flue gas, with alternate embodimentscapable of removing greater than 90% of the total mercury and greaterthan 95% of the total mercury. The HBr injection yielded approximately80% Hg oxidation and 75% Hg removal efficiencies from the baseline Hgconcentration of 5.5 μg/dscm, as measured at the ESP outlet. The HBrinjection yielded more than 90% Hg removal efficiency from the baselineHg concentration of 5.5 μg/dscm, as measured at the stack from thestationary Hg CEMS.

During the three days of active testing associated with Examples 1A-1E,the HBr injection was performed only on the first day for four hours andon the third day for ten hours. The residual effect of the HBr solutionlasted from 16 to 45 hours. From the initial HBr injection, mercurylevels never returned to baseline during the duration of the multi-daytesting program. Anecdotal reports after the test indicated that someresidual effect from the HBr was still occurring more than a week aftertesting was completed. Based on the stack Hg CEMS, the residual effectsof the HBr injection yielded more than 90% Hg removal efficiency. HBrinjections in Examples 1A-1E were performed with concentrations of theinjected solution ranging from about 1% HBr to about 4% HBr with higherconcentrations being used for higher total HBr injection rates. In analternate embodiment, HBr injection rates could be lower than those usedin Examples 1B and 1D to Account for those steady-state operationaleffects which are equivalent to the residual effects found in Examples1A-1E.

Residual effects of the HBr injection can be clearly seen in thestationary Hg CEMS trend shown in FIG. 6 which covers day 5 from 0224hours through day 6 at 0224 hours.

In separate prophetic examples, HBr would be injected at ratessufficient to maintain steady state mercury removal of 80%, 90%, or 95%of initial flue gas concentrations. Varying embodiments include theinjection of HBr with or without the corresponding use of Trona.

Injection rates of the HBr may be varied to account for the totalchlorine content of coal, and optimized based on chlorine content tomeet pollution control standards with an economy of HBr. HBr injectionrates may be varied to account for decreases in total available HBr dueto the introduction and the location of the introduction of Trona.Increasing either the HBr concentration or the trona free HBr resonancetime may overcome the adverse interaction between the HBr and trona.

Under the conditions of the present example, where the temperature inthe duct was above 700° F., the HBr injection chemical solution producedno substantial consumption of the injected NH₃ for NO_(X) control.Furthermore, the NO_(X) removal did not vary more than 5% during the HBrinjection process, which could indicate no negative impact on the SCRperformance or interaction with SCR catalysts.

In a prophetic example, the application of trona for control of acidgases is staged in the process such that the aqueous HBr or otherchemical solution oxidizes an amount of Hg(0) into Hg(II) sufficient tobring the HgT within the applicable pollution control standard.

Example 2

Example 2 involved a field trial of HBr injection at a 340 MW coal-firedelectric power generating station burning powder river basin coal. Theair pollution control system was comprised of a selective catalyticreduction unit for nitrogen oxide control, a cold side electrostaticprecipitator for particulate matter control, and an activated carboninjection system for mercury control. A schematic of the systemconfiguration is presented in FIG. 7. Referring now to FIG. 7, boiler2410 supplies flue gas to economizer 2420. Flue gas from a economizer2420 then passes through SCR 2430, air preheater 2440, and electrostaticprecipitators 2450 before passing through ID fan 2460 and be released tothe atmosphere by stack 2470. A majority of the test program wasconducted at near full load (317 to 348 MW), while several tests wereconducted at reduced load conditions (204, 299 MW). HBr injectionconcentrations ranged from 2.5 to 13.6 ppmvd over the test program.

The HBr injection system consisted of a series of lances installed atthe economizer 2420 outlet, before the SCR 2430, where the temperaturewas approximately 650° F. The injection lances were of the air assistedtype described later. The HBr injection was performed upstream of a SCR2430 system for the entire trial, and operation of the SCR was notmodified for the test program.

The test results showed over 90 percent oxidation when flue gas HBrconcentrations were 6 ppmvd and higher, and when SO₃ was not beingintroduced to facilitate ESP operation. FIG. 8 plots percent mercuryoxidation against the HBr oxidant concentration in the flue gas. Overthe initial baseline runs, Hg emissions averaged 3.3 pounds per trillionBritish thermal units.

In the present example, the existing cold side electrostaticprecipitator was used to control particulate emissions, and was found tobe very effective in removing oxidized mercury from the flue gas.Testing results indicated high Hg removals (around 90 percent) when HBrwas injected into the flue gas at concentrations above 6 ppmvd. Inletmercury was calculated from coal analytical results, and stack mercurywas analyzed using EPA Method 30B. Results from representative test runsare presented in Table 4.

TABLE 4 Gross HBr Inlet Unit Concentration Mercury Load in Flue Gas(lb/TBtu) Stack Mercury Hg Removal (MW) (ppmvd) [from coal] (lb/TBtu)(%) 329 0 6.8 3.2 52.9 329 0 6.8 3.4 50.0 342 2.5 6.25 1.08 82.7 342 3.36.25 0.73 88.4 204 4.9 5.78 0.74 87.2 204 5.3 5.78 0.34 94.1 338 10.19.73 .65 93.3 299 12.9 6.53 0.73 88.8 299 13.6 6.53 0.65 90.0

Baseline testing was conducted while injecting SO₃ into the flue gasstream prior to the ESPs 2450 to enhance ESP performance. The SO₃injection is used to significantly improve electrostatic precipitatorperformance with respect to particulate matter removal. During thetrial, it was found that the SO₃ interfered with the performance of theHBr reagent. It was also discovered that when injecting HBr without SO₃injection, SO₃ injection was not necessary and that both particulatematter and opacity control improved. The particulate test resultssuggest that the HBr could be used to replace the SO₃ for the purpose ofenhancing ESP operation. All reported runs other than baseline wereconducted without SO₃ injection. Results are presented in Table 5.

TABLE 5 Gross HBr Unit Injection Load Rate FPM CPM Total CPM Opacity(MW) (ppmdv) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (%) 329 0 (Base) 0.080.153 0.233 23.9 329 0 (Base) 0.071 0.109 0.180 23.7 342 2.5 0.053 0.0880.141 21.8 342 3.3 0.071 0.140 0.211 20.8 346 4.8 0.06 0.125 0.185 21.0345 5.3 0.045 0.126 0.171 20.4 317 7.5 0.059 0.148 0.207 16.2 299 13.20.037 0.088 0.125 14.3 *HBr Injection Rate represents HBr on a drybasis.

HBr injection was found to improve the control of flue gas filterableparticulate matter (FPM) and condensable particulate matter (CPM). Basedon parametric test results at various HBr injection rates at full loadconditions, filterable particulate matter decreased 17 to 30 percent andCPM decreased 13 to 24 percent compared to baseline conditions. Totalparticulate matter, the sum of condensed particulate matter andfilterable particulate matter, decreased 7 to 44 percent. HBr wasinjected at HBr injection point 2425. Powdered activated carbon wasinjected at injection point 2445.

Two runs were conducted with only PAC on days following the test programdescribed above. The PAC dosing during the two runs was 10 lb/MMacf,with a two-run average 93.4 percent Hg removal achieved. HBr injectionat 9.7 ppmdv, was combined with PAC injection at 2 lb/Mmacf on theprevious day, with a resulting Hg removal of 91.3 percent. These resultssuggest that HBr injection can reduce the amount of PAC required toachieve a given Hg removal.

HBr injection upstream of the SCR showed no significant adverse impactto SCR performance relative to NOx control. The average differencebetween baseline and the highest HBr injection dosing (13.2 ppmdv)indicated an 11 percent increase in NOx emissions. However, at an HBrinjection rate of 6 ppmdv and less, which would be typical for long-termoperation, the NOx emission factors were within the range of baselinevalues. The HBr injection lances were placed immediately upstream of theSCR unit in this test. Data was collected over an operating range of 315to 348 MW gross, and the NOx emission factor during the test rangedbetween 0.042 and 0.051 lb/MMBtu. As shown in FIG. 9, the NOx emissionfactor (measured at the stack) shows a slight upward trend withincreasing HBr concentration in the flue gas duct. Over this same range,the ammonia injection rate to the SCR shows a downward trend, whichwould explain some of the upward trend in the NO_(X) emission factor.

Example 3

A SCR is an air pollution control device used to control nitrogen oxideemissions. The technology employs a catalyst and typically either ureaor ammonia that is injected into a flue gas duct ahead of the catalystbed. As evidenced by Examples 1A-1E, injection of HBr upstream of an ESPdoes not adversely affect SCR performance, and has minimal impact on NOxcontrol. The presence of an SCR has been shown to promote oxidation ofHg without HBr dosing. The promotion of additional Hg oxidation may berelated to the large surface area of the SCR covered by ash that hasbeen treated with HBr. Referring to FIG. 10, SCR catalyst internalstructure 2010 may be in the form of a honeycomb or any otherconventional configuration. Internal structure 2010 develops an ashcoating 2240 such that the flue gas passing through SCR internal flowpath 2230 has a great degree of contact with ash coating 2240.

Example 4

FIG. 11 is an example of an ESP such as the ESP from Examples 1A-1E. Inthe present example, negatively charged electrode in the form of wire2330 and positively charged electrode, plates 2310 create an electricfield. The electric field between the electrodes drives particles in gasflow path 2340 to collect on plate 2310. HBr conditioned fly ashclinging to plates 2310 creates a high surface area reactive surfaceenhancing the effect of the HBr injection. Specifically, the deviceemploys a charging section that imparts an electric charge, normallynegative, to the particulate matter. The charged matter is attracted toan oppositely charged surface located perpendicular to the flow path.The ash collects on these surfaces and falls into a lower hopper wherethe ash can be removed.

When HBr is injected upstream of an ESP unit, it will associate withparticulate matter as previously discussed. Ash and Hg(2+) will becollected together on the ESP plates. Not wishing to be bound by theory,HBr is believed to increase a particles effective charge, increasingcollection efficiency. This intrinsic attraction associated with HBrcreates the potential for a high concentration of HBr on the ESP platesand associated ash coating.

Example 5

Example 5 was conducted on a commercial scale power plant having thesetup, coal characteristics, and pollution control equipment describedin FIG. 12. Referring now to FIG. 12, flue gas from boiler 1310 enterseconomizer 1320 after which the flue gas is divided into and treated intwo separate trains. HBr injection point 1325 is located at the inlet ofair preheaters 1330. Flue gas then passes through air preheater 1330,past activated carbon injection point 1335 and into electrostaticprecipitators 1340. Each electrostatic precipitator 1340 is followed bya pair of fabric filter/bag houses 1350 and the filtered flue gas fromfabric filter/bag houses 1350 is reunited in a single header 1360 beforebeing pushed to stack 1380 by ID fans 1370.

The boiler 1310 of Example 5 is a PC boiler with an electric generationcapacity of approximately 750 MW. This unit burns Texas lignite coalblended with powder river basin coal. The air pollution control systemconsists of a dry, “cold”-side electrostatic precipitator 1340 tocontrol particulate and mercury associated with the activated carboninjection system at the ESP inlet. A Compact COHPAC baghouse 1350 isoperated downstream of the ESP 1340 for further PM control which alsoyields additional control of Hg emissions. FIG. 12 shows the systemlayout and the injection/testing locations. A dilute HBr solution wasinjected at the air preheater inlet. Each COHPAC module 1350 included abypass valve, used to relieve excess bag filter pressure drop resultingin a portion of flue gas exiting to the stack unfiltered.

Two runs of baseline and eleven runs of HBr parametric testing wereperformed over a four day period to determine the impact on stackmercury (Hg) oxidization and removal. The unit load was observed to varyfrom 556 MW to 637 MW, and the untreated flue gas bypassing the COHPAC1350 was calculated to fluctuate between 5.1% and 16.5%. It is estimatedthat between 5% and 15% of untreated flue gas was routed to stack 1380during testing.

Table 6 shows overall Hg removal results based on coal Hg content and Hgmeasured at the stack 1380. Assuming all Hg entering the combustor incoal is volatilized, then approximately 57% of all Hg remains aselemental Hg throughout the entire air pollution control train underbaseline conditions. Approximately 40% of all Hg entering in coal isremoved under baseline conditions. Mercury oxidation and removal levelsresulting from HBr injections are also shown.

TABLE 6 Total Removal (combined Fabric Unit HBr Inlet Hg Filter and LoadDosing (total) Stack Hg ESP) Run (MW) (ppmvd) [lb/TBtu] (total)[Percent] 1 635 0 19.79 11.11 43.9 2 635 0 19.79 12.85 35.1 3 637 728.69 9.45 67.1 4 556 7.8 27.9 4.12 85.2 5 557 5.6 27.94 1.8 93.6 6 5621.7 23.43 11.06 52.8 7 563 3.7 23.4 8.54 63.5 8 562 6.2 23.39 3.12 86.79 635 7.1 24.95 5.49 78 10 632 5.8 24.95 6.88 72.4 11 632 6.7 25.09 5.6177.6 12 636 6.5 28.93 3.59 87.6 13 637 7.2 28.89 2.92 89.9

FIG. 13 shows Hg oxidation results at the inlet to the COHPAC system1350 and the stack 1380. A significant portion of Hg is oxidized andcaptured in fly ash by the ESP 1340. An additional amount of Hg iscaptured and removed by the COHPAC system 1350.

FIG. 14 shows normalized stack total Hg emission rates, normalized toremove the effect of flue gas bypassing the COHPAC system 1350. In otherwords, the corrected HgT emission rate is the estimated rate had therebeen no flue gas bypass. In addition, it is observed that conditioningof large air pollution control systems handling large amounts of fly ash(e.g., high lignite coal fly ash content) require conditioning time withHBr injection before final stable Hg emission rates are achieved. Astrong correlation was observed between the amount of HBr injected priorto each run and the mercury removed or oxidized. This is attributed tothe system slowly building up to an equilibrium content of HBr laden flyash in the system.

At 6.5 ppmvd injection concentration, the Hg oxidization efficiency is85.8% (normalized) as compared to baseline conditions.

At the 6.5 ppmvd HBr injection concentration, resulting stack Hgconcentration was approximately 4.4 lb/TBtu (un-normalized) because aportion of the flue gas bypassed the COHPAC, with a normalized value of3.7 lb/TBtu. FIG. 15 shows normalized total Hg removal efficiencyplotted against the cumulative HBr dosing over the test program. FIG. 16shows normalized total Hg in the stack (pounds per trillion Britishthermal units) plotted against the cumulative HBr dosing over the testprogram. As used in herein, cumulative dosing is presented as ppmvd*hrswhich is calculated as the area under a dosing curve that plots ppmvddosing of HBr against injection time measured in hours.

Example 6 Fabric Filter/Bag House

A fabric filter baghouse is an air pollution control device used toremove particulate matter such as ash from a flue gas stream, such as inthe configuration described in Example 5. Referring now to FIG. 17, atypical baghouse consists of an outer sealed enclosure 5000. A group ofholes 5010 is placed in the top of the enclosure into which porousfabric filters, typically referred to as bags 5020, are placed. The bags5020 are constructed of a porous media such as felt or other semi-porousmaterial that will allow air flow through the bags 5020 while collectingparticulate on the outer bag surfaces. A common plenum 5030 is placedacross the top of the baghouse to collect clean air that flows throughthe bags. Bags 5020 extend into the enclosure to a depth that maximizesash collection surface area. A device such as a fan 5040 provides themotive force to move particulate laden gas into the baghouse through aninlet duct opening Particulate matter that accumulates on the outer bag5020 surface is constantly renewed through bag cleaning, causing the ashto fall into a lower chamber 5050 of the baghouse where it can becollected and removed from the baghouse. This cleaning is commonlyperformed by periodic bag pulsing with an air jet 5060 that creates atemporary reverse flow through selected bags. Referring now to FIG. 18,which shows the configuration of an individual bag 2540 from a baghouse,bag 2540 is wrapped around a wire frame 2560. Flue gas travels in thedirection of flow indicated by arrow 2510 through bag 2540 andultimately up though the inside of bag 2540 as indicated by flowdirection arrow 2550. As this process occurs, solid particles, namelyfly ash particles 2520, form a particulate layer 2530.

HBr in the flue gas attaches to ash providing a reaction site for the Hgin addition to that which occurs in the gas phase between the injectedHBr and Hg. This particulate matter reaction site effect can occur inthe gas flow stream on individual ash particles in the gas stream, atthe duct walls (ash cake), on the particulate layer on fabric filterbags, or wherever particulate matter is present on a surface exposed toHBr dosing. As shown in FIG. 18, HBr treated fly ash having a bromineconcentration representative of one or more of the examples describedherein attaches to particulate layer 2530 forming an ash cake. The ashcake continuously builds as more HBr treated fly ash is filtered by bag2540. As flue gas containing mercury passes through the ash cake, asubstantial fraction of mercury in the flue gas attaches to the ashcake. When bag 2540 is pulsed mercury laden fly ash is dropped from bag2540 and removed from the baghouse. As the system cycles, fresh HBrtreated fly ash is always being added to bag 2540 and mercury is beingcontinuously removed by the ash cake with mercury laden fly ash beingperiodically removed by baghouse cleaning. The fabric filter provides alarge surface area for contact between the bromine containing ash andthe gas stream. Not wishing to be bound by theory, the Hg(0), as itcomes in contact with the active bromine species associated with the ashon the outer bag surface may react to form Hg(2⁺), which is removed fromthe flue gas along with the particulate matter collected on the bags.

Example 7

Testing was conducted at a coal-fired, front-wall-fired utility boilerwith an input duty rating of approximately 355 MW, gross shown in FIG.19. Flue gas from boiler 1700 flows into air preheater 1710 then throughelectrostatic precipitator 1720 and is ultimately fed through ID fan1730 into stack 1740 where it is released to the atmosphere. HBrinjections during the test occurred at injection point 1725 betweenboiler 1700 and air preheater 1710. The test program was designed toevaluate the degree of oxidation associated with HBr injection and toevaluate removal in an ESP.

The effectiveness of HBr in oxidizing Hg(0) in the present example isdemonstrated in the data shown in FIG. 20 which was collected from a Hgcontinuous emissions monitor with the sample extracted from the stack.During periods when HBr was not being injected, Hg ranged from about 2.3to 3.4 micrograms per dry standard cubic meter (μg/dscm). The initialHBr injection period represents a flue gas HBr concentration of 60ppmvd, and the second set represents a flue gas HBr injectionconcentration of 25 ppmvd.

Example 8

A 800 MW coal fired power plant was tested to evaluate HBr performance.Testing was conducted at loads that fluctuated between 747 and 836 MW.The coal fired during the test consisted of approximately 90 percentlignite coal and 10 percent PRB coal. The air pollution control trainincluded a PC Boiler, SCR, air preheater, cold side ESP, ID fan, WFGD,and stack. The air pollution control system also included a PAC systemfor Hg treatment. The PAC injection was turned off during HBr testing.During this test, HBr was injected at the SCR inlet at a temperature ofapproximately 850° F. Baseline HgT was 51.1 lb/TBtu based on coalmeasurements. Baseline HgT as measured at the WFGD inlet was 14.7lb/TBtu and 35.8 percent oxidized. These results show that 71.2 percentof the Hg was removed in the ESP prior to the WFGD inlet. Under baselineconditions, the WFGD Hg removal efficiency was 39.7 percent, with asystem Hg removal of 82.7 percent. Over the period of HBr injection andassociated testing, the HBr injection dose averaged 9.9 ppmvd, with anaverage system HgT removal efficiency of 90.2 percent over the airpollution control system. Over the period of injection, stack gasopacity averaged 10.1 percent compared to baseline of 13.1 percent.

Example 9

A 650 MW lignite coal fired power plant was tested to evaluate HBrperformance. Testing was conducted at loads that fluctuated between 472and 538 MW. In comparison to bituminous or sub-bituminous coal, lignitecoal is a low rank coal generally containing a low energy content withhigher levels of mercury, metals, moisture, and ash content. The airpollution control train included a PC Boiler, SCR, air preheater, coldside ESP, ID fan, WFGD, and stack. The air pollution control system alsoincluded a PAC system for Hg treatment. The PAC injection was turned offduring HBr testing. During this test, HBr was injected at the SCR inletat a temperature of approximately 850° F. Baseline HgT was 31.5 lb/TBtubased on coal measurements. Baseline HgT as measured at the WFGD inletwas 33.69 lb/TBtu and 5.8 percent oxidized. Under baseline conditions,the WFGD was removing 69.5 percent of the mercury, with a system Hgremoval of 66.9 percent. Over the period of HBr injection and associatedtesting, the HBr injection dose averaged 13.3 ppmvd, with an averagesystem Hg removal efficiency of 87.4 percent across the air pollutioncontrol system. Over the period of injection, stack gas opacity averaged8.3 percent compared to baseline at 10.6 percent.

Example 10

A steam boiler was tested to evaluate HBr injection. The air pollutioncontrol train associated with this boiler included a SNCR, dust hopper,air pre-heater, and FFBH. In this test, HBr was injected at the boileroutlet with Trona injected at the APH inlet. Testing with simultaneousTrona and HBr injection, or HBr alone, demonstrated Hg oxidationsignificantly lower than other comparable examples. At a 3 ppmvd dosing,Hg oxidation was 30.8 percent, and at 20 ppmvd dosing, Hg oxidation was45.3 percent. This test demonstrated the importance of proper HBrdistribution in the flue gas, since this test was conducted at a veryhigh injection nozzle turndown. This conclusion was reached based acomparison to the superior mercury removal results from a second similarunit described as Example 11.

Example 11

A steam boiler firing high fusion coal was tested to evaluate HBrinjection. The air pollution control train associated with this boilerincluded a SNCR, dust hopper, air pre-heater, and FFBH. Stack HgTreadings prior to HBr injection were 0.3 lb/TBtu and at the conclusionof the injection period (2 hr) were 0.05 lb/TBtu, and continued to dropafter injection stopped. This test demonstrates that HBr is effectivefor low Hg concentration sources.

Example 12

An evaluation of HBr injection was conducted at an ethanol productionfacility firing PRB coal to a 22 MW stream boiler. Air pollution controlequipment included SNCR for NOx reduction, Trona injection for SO₂control, and a FFBH for particulate control. The combustion trainincluded the boiler, a heat recovery steam generator, four-stageevaporator (heat exchangers), economizer, and FFBH. During the test,ammonia associated with the SNCR was injected in the boiler, HBr wasinjected after the second evaporator stage at a flue gas temperature of593° C., and Trona was injected before the economizer, about 35 feetdownstream from the HBr injection point.

During the test baseline run conducted at a boiler steam load of 150,000lb/hr, HgT emissions at the stack were 5.63 lb/Tbtu, with 11.7 percentoxidized with no Trona injection. With Trona injection, the baseline HgTemissions were 5.52 lb/Tbtu, with 9 percent oxidized. HBr was injectedat rates sufficient to cause concentrations ranging from 5 to 21 ppmvd.At the average test HBr concentration of 9.38 ppmvd, an average of 51.6percent oxidation was achieved, with a stack HgT emission average of3.19 lb/TBtu. During the HBr injection HgT emissions decreased by anaverage of 42.2 percent, as compared to the average baselineconcentration.

Example 13

Referring now to FIG. 21 of the drawings, HBr is loaded from 55 gallondrums by HBr drum pump, P3 into 48% HBr day tank, T1. Water passesthrough water filter F2 and is pumped by water gear pump P2 intodilution water supply line 1. HBr solution line 2 conveys aqueous HBrthrough 48% HBr filter, F1 to HBr metering pump P1 which in turnsupplies HBr to mixer line 3. HBr to mixer line 3 and dilution watersupply line 1 join prior to static mixer M1. Flow from static mixer M1travels through HBr solution filter F3 in line 4 where the flow isdivided into a series of 10 lines, lance lines 5, that feed lances thatdistribute the aqueous HBr into the process. Air is fed through airfilter F4 into atomizing air supply line 7 which supplies air toatomizing air distribution lines 6. Individual members of atomizing airdistribution lines 6 combine with individual members of lance lines 5 tosupply both air and HBr solution to the nozzles of the lances such thatthe individual nozzles are each supplied by one lance line 5 containingHBr solution and one atomizing air distribution line 6.

Example 14

FIG. 22 represents an example of a layout that may be used in thepractice of the various embodiments disclosed herein. Components of thelayout depicted in FIG. 22 include existing building wall 110, watermixing skid 120, titration area 125, heaters 130, HBr pump panel 135,HBr storage tank 140, safety shower/eyewash station 145, roll up door150, HBr drum storage 155, scrubber 160, scrubber vent 165, and sumparea with sump pump 170.

Example 15

Components of the layout depicted in FIG. 23 include water mixing skid175, HBr pump panel 180, chemical mixing room 190, sump area with sumppump 195, sump area with sump pump 200, air compressor on air compressorskid 210, heater 215, roll up door 220, and forklift 230.

Example 16

FIG. 24 represents an example of a layout that may be used in thepractice of the various embodiments disclosed herein. Components of thelayout depicted in FIG. 24 include containment wall 400, tanker truck410, sump area and sump pump 415, sump area and sump pump 420, safetyshower 425, HBr storage tank 430, scrubber 435, pump skid 440, blow downtank 445, pipe rack 450, and building 455.

Example 17

FIGS. 25A and 25B represent an example of a process layout that may beused in the practice of the various embodiments disclosed herein. HBrscrubber 500 removes HBr from vapors associated with HBr storage tank520. HBr drums 510 are located in drum containment area 505. HBr drums510 are unloaded by HBr drum pump 515 with the HBr passing through checkvalve 525 and into HBr storage tank 520. Pressure relief valve 530protects HBr storage tank 520 from over pressure. HBr delivery from HBrstorage tank 520 is accomplished by passing HBr through strainers 535and into acid metering pump feed line 538. HBr from acid metering pumpfeed line 538 is optionally routed to one of two HBr metering pumps 560which pump metered amounts of HBr into HBr feed line 562. HBr feed line562 contains pulse damper 565. Clean water supply line 545 is filteredand/or strained by dual basket water filters 550 and supplies cleanwater by way of water supply line 552. Water supply line 552 optionallyfeeds one of two water pumps 580 which delivers water by way of waterdelivery line 583. HBr feed line 562 mixes HBr with the water from waterdelivery line 583 in mixing line 569. The aqueous solution of HBrcontained in mixing line 569 is more completely mixed in in-line mixer570. The aqueous solution of HBr is then delivered to the nozzles foraddition to the flue gas. The HBr metering pumps may optionally beincluded within a panel or other enclosure. Portions of the process maydrain to a sump 595 containing sump pump 590. Sump pump 590 optionallydelivers waste from the sump to a waste storage container 598, or to awaste processing or recovery area.

Example 18

FIG. 26 represents an embodiment in which HBr and air are supplied tonozzles for injection into a flue gas. Compressed air is delivered tothe nozzles through main compressed air line 618. The pressure in maincompressed air line 618 is controlled by pressure control valve 615. Airis supplied to main compressed air line 618 by either air compressor 600or an alternate source of compressed air 610 which may optionally bepressure controlled by pressure control valve 605. Condensate is drainedfrom air compressor 600 by way of condensate drain line 620 andcondensate is drained from main compressed air line 618 by way ofseparator and condensate drain line 625. Main compressed air line 618branches into as many separate lines as are needed to feed a number ofnozzles sufficient to adequately distribute an HBr solution into theflue gas. Individual pressure control valves 630 regulate the airpressure delivered to individual nozzles by way of individual nozzlesair feed lines 670. Metered amounts of HBr are supplied to the nozzlesby way of main HBr supply line 650 and flush water is delivered to thelances by flush water delivery line 655. HBr solution and air are mixedin the atomizer nozzle assemblies 680 with individual nozzle air feedlines 670 providing air to the nozzles and individual HBr nozzle supplylines providing HBr solution to the nozzles.

Example 19

FIG. 27 represents a commercial scale embodiment having truck unloading,storage, and a system for handling HBr vapors. In that embodiment, HBrtruck unloading station 908 unloads HBr truck 905 utilizing nitrogensupply 900 into HBr storage tank 910. HBr is supplied to the aqueous HBrinjection portion of the process from the HBr storage tank 910 by way ofHBr supply line 965. Vapors from HBr storage tank 910 and optionallyother acidic vapors needing treatment are delivered to acid scrubber915. Acid scrubber 915 includes scrubber fill 920, mist eliminator pad922, scrubber vent 923, spray nozzles 925 and 926, and differentialpressure monitor 930. The contents of the scrubber are recirculated viascrubber recirculation pump 935 which feeds scrubber recirculation line937. The scrubber recirculation line 937 in turn feeds nozzle 925.Utility water supply 950 supplies water to both caustic storage tank 955and nozzle 926. Caustic storage tank 955 receives caustic from causticdrum 957. Scrubbing solution is provided to acid scrubber 915 fromcaustic storage tank 955 by way of caustic metering pump 960. Cartridgefilter 970 filters blowdown from acid scrubber 915 when the blowdown isin route to blowdown storage tank 980. The containment area 1008 issurrounded by containment wall 1010 which drains to sump 1000 which isemptied by sump pump 1005. Material from sump 1000 and blowdown fromacid scrubber 915 each enter blowdown storage tank 980 after passingthrough their respective check valves 975. Material from blowdownstorage tank 980 is both recirculated and delivered to the line to thesanitary sewer 992 by blowdown discharge pump 990. Sump pump 1005 alsodischarges to line to storm drain 995.

Example 20 Injection Nozzles

FIG. 28 represents a drawing of an embodiment of the aqueous HBrinjection nozzle. Aqueous HBr solution enters the nozzle 1200 throughliquid inlet 1205. HBr solution is injected into air/liquid mixingchamber 1220 at the point of liquid injection into the chamber 1210. Airis introduced at air inlet 1250 and the region of air/liquid mixing isdesignated in the figure by 1230. Sheer region 1260 and pintle plate1270 of nozzle 1200 enhance atomization.

FIG. 29 of the drawings plots the relationship of pressure, flow rate,and Sauter mean diameter for the nozzle. In one embodiment, a Sautermean diameter of less than 120 μm is selected. In distinct relatedembodiments, Sauter mean diameters of less than 80 μm and 30 μm areselected.

Example 21 Ammonium Bisulfate Reduction

The condensation of ammonium bisulfate results in a sticky material thatcan cause ash buildup and fouling problems. When HBr injection is usedin conjunction with a SCR, SNCR, or similar technologies that introduceammonia into the flue gas stream and produce ammonia slip, which isunreacted ammonia, HBr dosing is effective at reducing the formation ofammonium bisulfate. Ammonium bisulfate is produced when ammonia isintroduced into the flue gas and reacts with sulfur compounds, primarilysulfuric acid. If a system produces more than 2 ppmv of ammonia slip,substantial deposits of ammonium bisulfate can accumulate, particularlyin the downstream air preheater and/or ESP. The melting point ofammonium bisulfate is 297 degrees Fahrenheit (° F.), which can exist atthe bottom of an air preheater and equipment downstream of the airpreheater. During HBr injection, the ammonia slip is converted to aspecies other than ammonium bisulfate that does not have the sametendency to accumulate on duct and air pollution control equipmentsurfaces. Not wishing to be bound by theory, a probable alternativecompound is ammonium bromide. The mechanism of reactions within a fluegas are complex, however, ammonia may react with hydrogen bromide toform ammonium bromide by the following reaction.

NH₃+HBr→NH₄Br

Ammonium bromide, which melts at 846° F., and/or other compounds thatare the product of HBr injection in systems that have ammonia slipappeared to be leaving the system as solid particulate that can beeffectively removed from the gas stream using standard pollution controlequipment. Thus, at typical flue gas temperatures downstream of a SCRash having increased nitrogen or ammonia content can be collected in airpollution control equipment with other particulate matter.

An example of this effect is shown in the testing of a pulverizedbituminous coal fired power plant with a capacity of 325 MW. Nitrousoxides (NO_(X)) were controlled using low NO_(X) burners and a selectivecatalytic reduction system. A cold-side electrostatic precipitator wasused to control particulate matter, and a wet flue gas desulfurizationsystem was used to control sulfur dioxide. In the present example, HBrdosing occurred downstream of the SCR. Throughout the testing of thepresent example, all downstream solid samples collected (fly ash, FGDslurry) were also analyzed for ammonia content. The results of thisanalysis are summarized in Table 7. It was observed that the ashcollected in the ESP during HBr injection contained between 1.4 and 3.5times the ammonia present during baseline testing, with a consistentammonia injection rate over the test program. The results indicate thatduring HBr dosing the ammonia was being converted to a chemical speciesthat was not collecting in the system upstream of the baghouse, and wasbeing effectively removed in the ash. As used herein, “total ammonia”represents the results from a test that measures the amount of ammoniareleased into the headspace of a sample container when the ash isslurried in a 50% solution by weight of sodium hydroxide. Once theammonia released into the headspace is quantified, that value is used todetermine “total ammonia” as (mg NH₃/kg ash),

TABLE 7 NH₃ Injec- tion Total Slurry Total Rate Ash NH₃ In Cake NH₃ HBr(lb/ Weight Ash Weight InSlurry Date Time (ppmvd) hr) (g) (mg/kg) (g)(mg/kg) Day 1 AM 0.0 395 7.24 28 26.45 3.71 Day 1 PM 5.2 405 8.26 9126.15 3.39 Day 2 AM 1.2 480 7.71 94 27.77 3.43 Day 2 PM 3.0 470 7.53 4026.79 3.48 Day 3 AM 2.7 471 8.49 97 26.76 3.13

In a related embodiment, HBr and ammonia are injected into the flue gasat separate points where the flue gas is above 297° F. and ash havinggreater than 30 mg/kg total ammonia is removed from that flue gas. In afurther related embodiment, HBr is co-injected with ammonia into acoal-fired flue gas and ash having an ammonium bromide content of atleast 30 mg/kg ash is removed from that flue gas.

Example 22 Duct Perspective View

Referring now to FIG. 30, nozzles may be positioned within flue gas duct2010 at a distance 2014 sufficiently far from a substantial geometricchange 2016 in flue gas duct 2010 to allow for a reasonable distributionof flow across the cross-section of flue gas duct 2010. Placement ofinjection nozzles 2020 is at a downstream distance 2024 that issufficiently large to allow for vaporization of the injected fluid priorto the injected fluid reaching an internal obstruction 2028 withplacement of injection nozzles further being far enough from duct walls2036 to avoid any substantial liquid impingement on duct walls 2036 fromthe injected HBr. Specific nozzle placement is based on criteriaincluding temperature, spray distribution, flow path disturbances, andevaporation. In certain embodiments, injection of HBr takes place at atemperature below 900° F. but greater than 400° F. Not wishing to bebound by theory, within this temperature range the reaction kinetics areof suitable duration to achieve substantial reactions with HBr, andrapid evaporation of the HBr solution. The determination of residencetime necessary for proper nozzle placement is installation specific,based primarily on flow velocity, gas temperature, and turbulence. In atypical power plant application, less than 1 second is typicallyrequired to achieve evaporation and substantial reaction of the HBr withthe Hg. In certain embodiments injection may be configured to have anevaporation time of less than 0.5 seconds. Based on computational fluiddynamics modeling using air atomization with a nozzle designed toachieve 120 micron particle size, evaporation is achieved at a distanceof 4.4 feet from the injection nozzle at a duct temperature of 616° F.,and at a flue gas flow rate of 587 feet per minute (0.43 seconds forevaporation). Total residence gas times before the first air pollutioncontrol device is typically at least 3 to 10 seconds. Injection nozzles2020 are further positioned to allow for substantial distribution of thefluid within the duct cross section 2032 without substantial contact ofliquid with duct walls 2036.

Referring now to FIG. 31, four injection nozzles 2020 are positionedwithin flue gas duct 2010 such that injection nozzles 2020 are able todistribute liquid across a substantial majority of duct cross section2032 without causing large quantities of that liquid to come intocontact with duct walls 2036. Dashed lines in FIG. 31 indicate theperimeter of the spray pattern for each injection nozzle 2020 withinwhich the vast majority of liquid droplets originating from theinjection nozzles 2020 are vaporized. Nozzle configurations of thepresent embodiment inject the HBr into the flow stream. Injection of HBrmay be co-current injection to avoid potential nozzle pluggage issuesthat may arise with countercurrent injection. Spray patterns may beselected to maximize the coverage of droplets across the cross-sectionof the duct. The size of particles being injected is selected such thatthe droplet size causes quick evaporation into the gas stream to avoidliquid impingement on surfaces and to maximize the residence time of theHBr in vapor form. Due to flow variations across a duct, the delivery ofspray into a duct may not be uniform across its cross section. Placementand spacing may be selected to provide suitable residence time for thedroplets to evaporate and for the HBr to react with the Hg in the ductstream.

FIG. 32 represents a configuration similar to that shown in FIG. 31 inwhich an injection grid of 16 injection nozzles 2020 are used todistribute injection fluid throughout duct cross section 2032.

FIG. 33 shows the propagation of a droplet as it moves from an injectionnozzle 2020 toward the above referenced perimeter. The droplet 2022 iscontinuously vaporized as it approaches the perimeter and is completelyvaporized before reaching the perimeter. Selection of nozzle type andoperating pressure may be done to maximize the coverage of a duct by thearea within the perimeter without allowing the perimeter to intersectany walls of the duct.

Example 23

By way of example, various injection rates would have differentpotential concentrations of HBr in the ash for different HBr injectionrates because ash content varies across differing types of coal. Table 8indicates prophetic calculations of HBr ash concentration for variousinjection rates and ashes.

TABLE 8 Dose Rate 1 ppmvd 6 ppmvd 60 ppmvd High fly ash  67 ppm wt 400ppm wt 4000 ppm wt lignite Low fly ash lignite 117 ppm wt 701 ppm wt7008 ppm wt PRB 292 ppm wt 1750 ppm wt  17500 ppm wt 

Example 24 Fly Ash Preparation

Fly ash obtained from a coal fired boiler burning lignite coal was usedfor the purpose of coating fly ash with Hg and HBr, simulating ashwithin a flue gas stream or on a flue gas duct inner surface. 30micrograms of HBr was first applied to sorbent module 1605 containingapproximately 200 grams of fly ash, followed by 30 ug of Hg.

Referring now to FIG. 34, the experimental apparatus included sorbentmodule 1605, approximately 1.5 inch diameter by 4 inches long. Ashlayers 1610 were separated by glass wool layers 1620, with sorbentmodule 1605 enclosed in heater 1630 to maintain a temperature of 400° F.A mixture of HBr in air was introduced from a gas handling bag 1636through glass tubing 1635, heater 1630, glass tubing 1650 and intosorbent module 1605, with motive force provided by a vacuum pumpconnected to system vent line 1670. Heater 1640 was controlled to atemperature of 400° F. Subsequent to introducing HBr, Hg in an airmixture was introduced from gas handling bag 1636, traveling throughglass tubing 1635, heater 1630, glass tubing 1650, and into sorbentmodule 1605. During the addition of both HBr and Hg, water was injectedinto heater 1640 using syringe pump 1645 to create gas stream 1650 witha moisture content of 7 percent.

Example 25 Organohalogens

In a prophetic example, an organohalogen is combusted such that thecombustion products come into intimate contact with a combustion exhaustcontaining mercury. Referring now to FIG. 35, reagents 2100 areintroduced into burner 2110 to create an exhaust containing mercurywhich enters exhaust conduit 2115. Organohalogen supply line 2135provides organohalogen in a manner that causes mixing with the reagents.In one embodiment of the present example, reagents 2100 comprise coaland combustion air and organohalogen supply line 2135 suppliesorganohalogen that is mixed with the coal prior to entering burner 2110.Exhaust in exhaust conduit 2115 cools to below 500° C. at transitionpoint 2120. The organohalogen may be ethylbromide or bromoform. Exhaustconduit 2115 should be configured to have sufficient residence time andmixing to promote the formation of HBr. Injection of treatment gas 2140may be by direct injection or through a series of injection tubes suchthat adequate mixing occurs allowing for sufficient contact of the HBrwith the flue gas stream in exhaust conduit 2115. At the end of exhaustconduit 2115, the exhaust is discharged into the atmosphere at stack2125. In an alternate embodiment, dibromomethane is the organohalogenthat is combusted. In a further alternate embodiment, dibromoethane isthe organohalogen that is combusted. In a still further alternateembodiment, ethylene dibromide is the organohalogen that is combusted.In a series of separate but related embodiments, any one of thecompounds of FIGS. 38A-38E may be used as the organohalogen that iscombusted.

Brominated organohalogens used in the present example may have one ormore of the following characteristics: low toxicity, not beingclassified as a known carcinogen, containing carbon, having greater than50% bromine by weight, and being liquid at standard temperature andpressure.

Equipment used to effect the chemical reaction of the organohalogen maybe a thermal oxidizer, a chemical reaction vessel, or a similar devices.In one embodiment, pyrolysis or combustion of the organohalogen takesplace at a temperature above 1650° F.

Example 26 Organohalogens

Referring now to FIG. 36, the present example has features andcharacteristics equivalent to those of Example 25 with the exceptionthat organohalogen supply line 2135 injects organohalogen directly intoburner 2110.

Example 27 Organohalogens

Referring now to FIG. 37, the present example has features andcharacteristics equivalent to those of Example 25 with the followingexceptions. Treatment gas 2140 is added to exhaust conduit 2115 aftertransition point 2120. An organohalogen introduced at organohalogensupply line 2135 is combusted in standalone burner 2130, rather thanbeing introduced with reagents 2100, to produce treatment gas 2140. Theconfiguration of standalone burner 2130 relative to exhaust conduit 2115should be such that it promotes the formation of HBr through sufficientresidence time. Injection of treatment gas 2140 may be by directinjection or through a series of injection tubes such that adequatemixing occurs allowing for sufficient contact of the HBr with the fluegas stream in exhaust conduit 2115.

Example 28

In a prophetic example, flue gas desulfurization (FGD) is carried out byone of several known wet scrubbing techniques (including but not limitedto inhibited oxidation, forced oxidation, limestone, and lime basedsystems). Under these circumstances, HBr injection is carried out priorto the wet FGD allowing for enough residence time to sufficientlyconvert Hg(0) into Hg(II) to meet applicable pollution controlstandards.

Example 29 Low Temperature Oxidation

Certain applications, such as post-process treatment of cement kiln fluegases, would require introduction of the HBr solution at temperatureswell below those seen in coal-fired power plants. Mercury emissions fromcement kilns are often significantly higher than coal-fired plants dueto native mercury in the limestone feed materials. A series of testswere conducted to evaluate the effectiveness of HBr to oxidize elementalmercury at temperatures ranging from 150 to 250° F.

Mercury vapor was generated by passing filtered and decontaminatedambient air at a controlled flow rate over a small amount of elementalmercury to create concentrations of mercury (1 to 20 μg/m³) in the gasstream. Inlet mercury concentrations (pre-HBr injection) were monitoredwith a vapor mercury analyzer (Jerome 431X). The gas stream was heatedand maintained at temperatures ranging from 100 to 250° F. Once heated,HBr vapor was introduced into the gas stream to initiate the oxidationprocess of the elemental mercury. Controlled vaporization of HBrsolution was facilitated by injecting HBr solution into a heated chamberat a predetermined flow rate and flashing the liquid into a small purgeflow. The vaporized HBr was diluted with dry air to prevent condensationof the HBr. A mixer downstream of the HBr vaporizer supplied withdilution air mixed the dilute Hg gas stream to facilitate the reactionbetween HBr and elemental mercury. The mixed Hg/HBr stream was passedthrough a tube reactor for limited added retention time. After the tubefurnace, the gas stream was bubbled through a glass impinger ofpotassium chloride (KCl) where the oxidized mercury was removed.Finally, a second vapor mercury analyzer (Jerome 431X) was used tomonitor the elemental mercury concentrations of the gas stream, prior toexiting the system and going into the hood.

Test conditions included run times of 30 to 60 minutes and ambient airas the feed gas at feed rates of 0.1 to 1 scfm between 100 to 250° F.Gas stream mercury concentrations ranged from 1 to 100 μg/m³. HBrsolution concentrations ranged from 0.1 to 3.0%. HBr solution flow ratesranged from 0.01-3.0 mL/hr creating gas stream HBr concentrations from 1to 25 ppmvd. The impinger solution was an aqueous 1N KCl solution.

Results for a typical test run included a run time of 2 hours, a gasstream flow rate of 3.3 liter/min, a reactor internal temperature of125° C., a gas stream HBr concentration of 3.8 ppmvd at times when 0.8ml/hr of 0.28% HBr solution was added.

Table 9 below gives results of a typical run. The desired effect fromthe HBr addition increases over a few minutes at the start, then levelsoff at about 85% for this particular set of conditions.

TABLE 9 Results of HBr Treatment of Mercury in Effluent Gas Hg HgConcentration Concentration Time¹ at Inlet at Outlet Percent Hg (min.)(μg/cu meter) (μg/cu meter) Removal Start 40 25 37.5 5 40 25 37.5 15 4020 50 25 40 12 70 45 40 6 85 60 40 5 88 75 40 6 85 ¹From InitialInjection of HBr.

Similar experiments confirm that HBr is effective at aggressivelyoxidizing Hg and allowing collection of the mercury salt by standardmethods at temperatures as low as 190° F.

Example 30

In a series of prophetic examples, HBr may be delivered into the fluegas in various forms including, fully vaporized concentrated aqueousHBr, partially vaporized concentrated aqueous HBr, fully vaporizeddilute aqueous HBr, and partially vaporized dilute aqueous HBr.

Example 31

In a series of prophetic examples, by varying residence time, mixingconditions, and other process variables, coal may be combusted accordingto the methods described herein such that a halogen containing additivereacts with the mercury from the coal and, on a weight basis, thehalogen containing additive is supplied at 300 ppmvd or less of thetotal of coal and additive supplied and less than 50 weight percent ofthe mercury in the coal is released to the atmosphere. In relatedembodiments, the additive is supplied at 250 ppmvd or less, 200 ppmvd orless, 150 ppmvd or less, and 100 ppmvd or less. Conversion rates inthese embodiments may be such that less than 20 weight percent of themercury in the coal is released to the atmosphere and in someembodiments less than 10 or even 5 weight percent of the mercury in thecoal is released to the atmosphere. Not wishing to be bound by theory,HBr on a weight basis may have mercury removal capabilities that greatlyexceed those of calcium bromide due to multiple factors. First, themolecular weight of HBr is lower than that of calcium bromide. Second,because HBr may be applied after combustion rather than prior tocombustion, a greater quantity of HBr may be available for reaction withmercury. Finally, reaction chemistry and other interactions in the fluegas may favor HBr as a reactant.

Example 32 Calcining

In a prophetic example, one or more of the techniques described hereinmay be utilized to remove mercury from the exhaust of a calciningprocess, such as the calcining process of cement production. An examplecalcining application is presented in Figure U. In this example, HBr isapplied in conjunction with or without PAC injected in a transition ductbetween the primary and secondary fabric filter baghouse. HBr mixes withthe flue gas, oxidizing the mercury, which is then adsorbed onto the PACor, in the absence of PAC, the treated HBr-impregnated fly ash. The flyash and/or PAC is then collected by the Secondary Fabric Filter Baghouse(SFFB). As shown in FIG. 39, raw materials, (limestone, coal, mineralsfor cement production) are introduced into the system as process stream3400. The raw materials are conveyed to the Kiln/Calciner whereoxidation and calcination occurs. Mercury and other volatile elementsand compounds are evolved into the flue gas stream 3500 and conveyedthrough various process steps to a Primary Fabric Filter Baghouse(PFFB). Ash collected in the Primary Baghouse, which can be sold as abyproduct of the process, exits the system as stream 3460, or isrecycled back to the front of the process as stream 3410. Because alarge fraction of the ash is recycled back to the front of the process,mercury collection in the PFFB is unproductive and discouraged, as itwould tend to increase the equilibrium concentration of mercury andother contaminates in the final product moving to the clinker cooler asstream 3420. The final product is cooled, milled and shipped, exitingthe process as stream 3450. The gas stream is cooled somewhat by passingthrough the PFFB in route to the SFFB. The flue gas is treated tooxidize and remove mercury in the transition between the PFFB and theSFFB, stream 3510. HBr is pumped from storage via stream 3480 into theHBr Injection System, described in detail elsewhere in this document.The HBr is then injected under pressure through stream 3490 into thetransition duct, 3510, where the HBr evaporates and reacts withelemental mercury. A significant portion of the HBr not reacted directlywith the mercury proceeds to the SFFB where it associates with the ashto form a reactive layer of material cake on the surface of the fabricfilters. Most of the remaining elemental mercury is oxidized andcollected within the filter cake. Mercury already in an oxidized form isremoved by the filter cake. The cleaned flue gas exits the system asstream 3520 and is released to the atmosphere. The mercury-laden ashexits the system as stream 3470 and can be sent to reclaim metals,including mercury, or conveyed to the appropriate disposal site.

As described in the test associated with Example 29, essentiallycomplete oxidation of elemental mercury can be achieved at 190° F.,given that no moisture is condensed on contacted surfaces.

Example 33 Ore Roasting

In a prophetic embodiment, one or more of the techniques describedherein may be utilized to remove mercury from the exhaust gas of an oreroaster such as the ore roasters associated with gold mining.

Example 34 Coke Ovens

In a prophetic example, one or more of the techniques described hereinmay be utilized to oxidize and remove mercury from coke oven exhaust.The U.S. EPA has stipulated that non-recovery type coke ovens aredesignated as the Maximum Achievable Control Technology for cokingoperations. This example addresses the use of the above described HBrmercury control technologies on such a system. In a non-recovery cokeoven, coke is produced by heating coal in an enclosed oven whilemaintaining a chemically reducing environment in and around the coalbed. FIG. 40 shows an example of one possible production plantconfiguration in which HBr injection is utilized. In this application,multiple coke ovens are constructed side by side to create two banks of30 ovens. In practice, the number of ovens can vary, but banks of 25 to50 ovens are typical. Multiple batteries of ovens are combined to yieldplant sites with over 200 ovens. Up to 30 tons of coal is introducedinto each of the ovens 4100 and maintained at temperatures of over 2000°F. for 24 to 48 hours, until all volatile matter is evolved and onlyfixed carbon and trace minerals remain. The hot exhaust gases are ductedfrom the ovens to a “common tunnel” 4105 that runs the length of eachbank. The common tunnel collects and conveys the gases through hightemperature ducting 4110 to any of multiple Heat Recovery SteamGenerators 4120, where waste heat from the process is used forco-generation. After heat is removed, the exhaust gases are conveyedthrough ducting to a manifold 4130 where the gases are remixed into asingle duct. The collected gas passes through a spray dryer absorber4135 where sulfur dioxide is removed. The gases then pass throughducting 4140 to a fabric filter baghouse 4145 for particulate removaland through the induced draft fan 4150 and to a common stack 4160 intothe atmosphere.

Mercury is emitted from the system through direct evolution of elementalmercury (which occurs naturally in the coal) into the exhaust gases.Some of the native mercury may already be in an oxidized form. Thismercury is thermally decomposed and emitted as elemental mercury. Themercury emissions can be controlled by introducing HBr at location(s)4125 upstream of the spray dryer absorber. The mercury will be oxidizedand can be collected in the spray dryer or downstream in the fabricfilter baghouse. Powdered activated carbon may be injected upstream ofthe fabric filter baghouse, if required to achieve site-specific mercuryemission removals.

Viewing the above practiced embodiments together, the ratio of surfacearea to scfm of gas being treated appears to be an important metric forthe performance of the HBr treatment. As used herein, the term“treatment area to flue gas flow ratio” should be calculated as follows:

${{treatment}\mspace{14mu} {area}\mspace{14mu} {to}\mspace{14mu} {flue}\mspace{14mu} {gas}\mspace{14mu} {flow}\mspace{14mu} {ratio}} = \frac{{surface}\mspace{14mu} {area}\mspace{14mu} {covered}\mspace{14mu} {by}\mspace{14mu} {conditioned}\mspace{14mu} {ash}\mspace{14mu} {sorbent}\mspace{14mu} \left( {ft}^{2} \right)}{{Standard}\mspace{14mu} {cubic}\mspace{14mu} {feet}\mspace{14mu} {per}\mspace{14mu} {minute}\mspace{14mu} {of}\mspace{14mu} {flue}\mspace{14mu} {gas}\mspace{14mu} {treated}\mspace{14mu} \left( {{ft}^{3}/\min} \right)}$

As used herein, the term “effective quantity” designates a quantity of acompound sufficient to bring a flue gas not otherwise compliant with amercury pollution control standard into compliance with the mercurypollution control standard. As used herein, the term “mercurycontaminated gas” designates a gas having a mercury content of at least0.5 μg/m³ at standard conditions. As used herein, the term “diluteaqueous HBr” designates an aqueous HBr solution having 30% HBr or less.As used herein, the term “concentrated aqueous HBr” designates anaqueous HBr solution having more than 30% HBr. As that phrase is usedherein, “HBr susceptible materials” designates materials that woulddegrade in a way that would make them not useful for their intendedpurpose after a 12 month exposure to a 5.0% solution of HBr at 200° F.As that term is used herein in the context of HBr contacting varioussurfaces, “substantial accumulation” designates an accumulation of HBrsufficient to degrade the surface in a way that would requirereplacement of the surface if the accumulation were present for a year.As that term is used herein, “native particulate matter” representsparticulate matter that originates with the gas stream being treated asopposed to being injected into a gas stream as a reagent or additive. Anexample of native particulate matter is native fly ash entrained in aflue gas from the burning of coal. As that phrase is used herein, “dopedparticulate matter” designates particulate matter having an activebromine content greater than 20 ppm by weight. Ratios and concentrationsdescribed herein are by weight unless there is an indication to thecontrary. As that term is used herein, “media” designates an interveningsubstance capable of substantially changing the composition of the gaswith which it interacts. Examples of media as that term is used hereinwould include scrubber liquid, powdered activated carbon, ash, andfabric filters. In the context of burning an organohalogen, asubstantial quantity of any particular organohalogen is a quantity ofthat organohalogen sufficient to decrease the quantity of mercury in theform of elemental mercury (Hg(0)) by 10% in a flue gas that is beingtreated as compared to the quantity of mercury in the form of elementalmercury that would be present in the flue gas if the particularorganohalogen was never introduced. As that phrase is used herein,“organically bound bromine” represents bromine atoms that are directlybound to a carbon atom in the relevant molecule.

There are, of course, other alternate embodiments which are obvious fromthe foregoing descriptions of the invention, which are intended to beincluded within the scope of the invention, as defined by the followingclaims.

1. A method of treating mercury contaminated gas comprising: a. introducing a hydrogen halide selected from HBr and HI into a mercury contaminated gas stream containing a quantity of particulate matter at an introduction rate sufficient to create a concentration of at least 0.1 ppmvd; b. wherein greater than 50% of all particulate matter in the mercury contaminated gas stream is a native particulate matter; c. contacting a quantity of active bromine with the native particulate matter; d. creating a doped particulate matter; e. coating a filtration media with the doped particulate matter; and f. passing a portion of the mercury contaminated gas stream through the doped particulate matter on the filtration media.
 2. The method of claim 1 wherein the hydrogen halide selected from HBr and HI is HBr.
 3. The method of claim 1 wherein the introducing of a hydrogen halide selected from HBr and HI occurs at a point where the mercury contaminated gas stream is less than 750° F.
 4. The method of claim 1 wherein the introducing of a hydrogen halide selected from HBr and HI occurs at a point where the mercury contaminated gas stream is greater than 180° F.
 5. The method of claim 1 wherein the mercury contaminated gas stream is a byproduct of the combustion of coal having a chlorine content of less than 300 ppm by weight and a mercury content greater than 50 ppb by weight.
 6. The method of claim 1 wherein the introducing of a hydrogen halide selected from HBr and HI is at an introduction rate creating a concentration of at most 15 ppmvd.
 7. A method of treating mercury contaminated gas comprising: a. introducing dilute aqueous HBr into a mercury contaminated gas stream containing a quantity of particulate matter at an HBr introduction rate sufficient to create a HBr concentration of at least 0.1 ppmvd; b. contacting a quantity of active bromine with a portion of the quantity of particulate matter; c. creating a doped particulate matter from the quantity of active bromine and the quantity of particulate matter; and d. inducing electrostatic forces thereby removing greater than 50% of the doped particulate matter from the mercury contaminated gas stream.
 8. The method of claim 7 wherein mercury is collected on the doped particulate matter.
 9. The method of claim 7 wherein the electrostatic forces occur within an electrostatic precipitator.
 10. The method of claim 7 wherein the introduction of dilute aqueous HBr is at an introduction rate creating a HBr concentration of at most 10 ppmvd.
 11. A method of treating mercury contaminated gas comprising: a. introducing a mercury contaminated gas into a conduit; b. wherein the conduit comprises HBr susceptible materials; c. wherein the mercury contaminated gas has an initial quantity of mercury; d. wherein the conduit has an inner surface; e. injecting a quantity of dilute aqueous HBr into the conduit; f. wherein the injection of the quantity of dilute aqueous HBr is through a plurality of nozzles at an HBr injection rate sufficient to create a HBr concentration of at least 0.1 ppmvd; g. wherein a spray pattern of the plurality of nozzles covers a majority of a cross-section of the conduit; h. wherein there is no substantial accumulation of aqueous HBr on the inner surface; and i. contacting the mercury contaminated gas with a media thereby removing at least 50% of the initial quantity of mercury from the mercury contaminated gas.
 12. The method of claim 11 wherein the injection of the quantity of dilute aqueous HBr occurs at a point where the mercury contaminated gas is between 180° F. and 750° F.
 13. The method of claim 11 wherein the injection of the quantity of dilute aqueous HBr occurs at a point where the mercury contaminated gas is between 180° F. and 750° F.
 14. The method of claim 11 wherein the plurality of nozzles is a plurality of dual fluid nozzles and the quantity of dilute aqueous HBr has an HBr concentration greater than 0.25%.
 15. The method of claim 11 wherein the injection of the quantity of dilute aqueous HBr is through a plurality of nozzles at an HBr injection rate creating a HBr concentration of at most 10 ppmvd.
 16. A method of treating mercury contaminated gas comprising: a. introducing active bromine into a treatment zone; b. passing a mercury contaminated gas stream through the treatment zone; c. wherein the mercury contaminated gas stream contains nitrogen; d. wherein a residence time of the active bromine in the treatment zone is at least 1.1 times that of a residence time of the nitrogen in the treatment zone; and e. removing at least 50% of the mercury contained in the mercury contaminated gas stream from the mercury contaminated gas stream with a particulate control device.
 17. The method of claim 16 wherein the introducing of active bromine into the treatment zone is at an introduction rate that creates an active bromine concentration of between 0.1 ppmvd and 10 ppmvd.
 18. A method of treating flue gas comprising: a. introducing active bromine into a treatment zone; b. introducing ammonia into the treatment zone; c. passing a quantity of flue gas having an initial ash content and having an initial mercury content through the treatment zone; d. collecting at least 80% of the initial ash content in a particulate control device; and e. collecting at least 50% of the initial mercury content in the particulate control device.
 19. The method of claim 18 wherein the ash collected in the particulate control device has a total ammonia content of at least 40 ppm by weight.
 20. The method of claim 18 wherein the ash collected in the particulate control device contains at least 60% of the initial mercury content.
 21. The method of claim 18 wherein the introducing of active bromine into the treatment zone is at an introduction rate creating an active bromine concentration of between 0.1 ppmvd and 10 ppmvd.
 22. A method of treating flue gas comprising: a. passing a flue gas through a treatment zone; b. introducing a hydrogen halide selected from HBr and HI into the treatment zone at a rate sufficient to create a concentration of at least 0.1 ppmvd; c. producing a conditioned ash sorbent on a plurality of surfaces of the treatment zone such that the treatment zone has a treatment area to flue gas flow ratio of at least 0.3 min/ft; and d. continuing the introduction of the hydrogen halide selected from HBr and HI into the treatment zone until the treatment zone attains a cumulative injection level of 60 ppmvd*hrs.
 23. The method of claim 22 wherein the hydrogen halide selected from HBr and HI is HBr.
 24. The method of claim 22 wherein the introducing of the hydrogen halide selected from HBr and HI into the treatment zone is at an introduction rate that creates an active bromine concentration of less than 10 ppmvd.
 25. A method of treating a mercury contaminated gas comprising: a. combusting a fuel containing at least 50 ppb mercury by weight; b. combusting a substantial quantity of a treatment composition; c. wherein the treatment composition is selected from: i. 2-(bromomethyl)oxirane; ii. 1-bromopropan-2-one; iii. 1-bromobutane; iv. 2-Bromobutane; v. 1-bromo-2-methylpropane; vi. 1-bromo-3-methylbutane; vii. 2-bromo-2-methylbutane; viii. 1-bromopentane; ix. 2-bromopentane; x. 2-bromopentane; xi. 1-bromo-2-ethoxyethane; xii. bromobenzene; xiii. 2-bromopyridine; xiv. dibromomethane; xv. 1,2-dibromoethene; xvi. 1,1-dibromoethane; xvii. 1,2-dibromoethane; xviii. 2,2-dibromoacetonitrile; xix. 2,3-dibromoprop-1-ene; xx. 2-bromoacetyl bromide; xxi. 1,2-dibromopropane; xxii. 1,3-dibromopropane; xxiii. 1,3-dibromobutane; xxiv. 1,4-dibromobutane; xxv. 1,3-dibromopropan-2-ol; xxvi. 2,3-dibromopropan-1-ol; xxvii. 1,4-dibromopentane; xxviii. 1,5-dibromopentane; xxix. 1-bromo-2-(2-bromoethoxy)ethane; xxx. (1R,2R)-1,2-dibromocyclohexane; xxxi. 1,6-dibromohexane; xxxii. dibromomethylbenzene; xxxiii. 1,8-dibromooctane; xxxiv. 1,1,2-tribromoethene; xxxv. 2,2,2-tribromoacetaldehyde; and xxxvi. 1,1,2,2-tetrabromoethane; and d. comingling at least one product from the combusting of the fuel and at least one product from the combusting of the substantial quantity of the treatment composition.
 26. The method of claim 25 wherein the treatment composition is bromoethane.
 27. The method of claim 25 wherein the treatment composition is bromoform.
 28. The method of claim 25 wherein the treatment composition is dibromomethane.
 29. The method of claim 25 wherein the treatment composition is 1,2-dibromoethane.
 30. The method of claim 25 wherein the treatment composition is 1,2-dibromoethene.
 31. A method of controlling mercury emissions comprising: a. combusting a quantity of fuel having an initial mercury content by weight and an initial molar quantity of mercury atoms thereby producing at least one fuel combustion product; b. combusting a quantity of a treatment composition having an initial organically bound bromine content by weight and an initial molar quantity of organically bound bromine atoms thereby producing at least one treatment composition combustion product; c. wherein the initial organically bound bromine content by weight makes up at least 10% of the total weight of the quantity of the treatment composition; d. configuring the combusting of the quantity of fuel and the combusting of the quantity of treatment composition such that the at least one fuel combustion product and the at least one treatment composition combustion product mix and such that greater than 30% of the initial molar quantity of mercury atoms are oxidized; e. wherein the initial molar quantity of organically bound bromine atoms is greater than 500 times the initial molar quantity of mercury atoms.
 32. The method of claim 31 wherein the initial organically bound bromine content by weight makes up at least 20% of the total weight of the quantity of the treatment composition.
 33. The method of claim 31 wherein the initial organically bound bromine content by weight makes up at least 50% of the total weight of the quantity of the treatment composition. 